1. Field of the Invention
Embodiments of the present invention generally relate to methods and apparatus for forming a subsea wellbore. More specifically, embodiments of the present invention relate to methods and apparatus for anchoring a conductor or casing in a subsea wellbore.
2. Description of the Related Art
A wellbore for accessing hydrocarbon-bearing formations is typically formed by first drilling to a predetermined depth using a drill string. The drill string is often rotated by a top drive or rotary table on a surface platform or rig, or by a downhole motor mounted towards the lower end of the drill string. After drilling to the predetermined depth, the drill string is removed and a string of casing is lowered into the wellbore. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted to fill the annular area defined between the outer wall of the casing and the borehole with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, the well is drilled to a first designated depth. After removing the drill string, a first string of casing or conductor pipe is then run into the wellbore and set in the drilled out portion of the wellbore. Cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing, or liner, is run into the drilled out portion of the wellbore. The second string is typically set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string may then be fixed, or “hung” off of the existing casing by the use of slips which utilize slip members and cones to frictionally affix the new string of liner in the wellbore. The second casing string is then cemented. This process is typically repeated with additional casing strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing.
In the construction of offshore wells, a conductor pipe is typically installed in the earth prior to the placement of other tubulars. The conductor pipe, typically having a 36″ or 30″ outer diameter (“OD”), is jetted, drilled, or a combination of jetted and drilled into place. Placement depth of the conductor pipe may be approximately from 200 feet to 500 feet below the mud line. The conductor pipe is typically carried in from a drill platform on a drill string that has a bit or jetting head projecting just below the bottom of the conductor pipe, which is commonly referred to as a bottom hole assembly (“BHA”). The conductor pipe is placed in the earth by jetting a hole and if necessary partially drilling and/or jetting a hole while simultaneously carrying the conductor pipe 10 into the hole.
The general procedure for drilling the hole below the conductor pipe to install the structural or surface casing is to drill with a BHA on the end of the drill string used to run the conductor pipe in the hole. Surface casing refers to casing run deep enough to cover most know shallow drilling hazards, yet the casing is typically located above any anticipated commercial hydrocarbon deposits. The BHA will as a minimum consist of a drilling or jetting bit. The BHA may also contain a mud motor, instrumentation for making geophysical measurements, an under reamer, stabilizers, as well as a drill bit or an expandable drill bit. After, the hole is drilled for the next string of casing, the surface casing is run-in and installed concentrically with the conductor.
The conductor, as the outermost casing, handles most of the anchor responsibilities. In many offshore drilling operations, motion or energy from the sea and the drilling activity is transferred through the casings. Because the casings are installed concentrically, the motion or energy is also transferred radially to the conductor. In addition to mechanical movement, the conductor also experiences thermal stretch and contraction associated with the changing temperature of the fluids. Over time, these stresses cause failure of the cement around the conductor as well as fatigue in the casings. A poor cement job also negatively affects the conductor's ability to anchor the casings because of the presence of gaps in the annular area resulting in insufficient contact area with the borehole. Poor cement jobs are more common when cementing near the sea floor where there is more unconsolidated soil. Thus, a conductor is more prone to movement in offshore drilling operations.
A need, therefore, exists for apparatus and methods of anchoring a conductor in a subsea wellbore.